November NG Slips to $2.975 as Mild Weather Masks 45 Bcf Storage Surplus and First-Ever 20 Bcf/d LNG Demand

November natural gas futures on NYMEX traded at $2.975 per MMBtu at 11:45 a.m. in New York on Tuesday, down 8.3 cents, or 2.7%, from Monday’s settlement near $3.058. The prompt contract tested below $3.00 support in early trade and stayed there through midday. Henry Hub spot gas averaged $3.121 in morning trading, a premium of 14.6 cents to the futures contract. The November contract had settled at $3.24 on October 15 and touched $3.30 earlier in the month as Hurricane Isaias approached the Gulf. From that peak, the contract has lost 32.5 cents, or 9.8%, in under two weeks.

The thesis for this forecast is direct. The break below $3.00 is a weather-driven dip inside a market that is tightening structurally, not the start of a new downtrend. Mild shoulder-season forecasts and recovering production are weighing on the prompt month right now. Against that, feedgas to U.S. LNG export terminals hit a record 20.7 Bcf/d on Monday, surpassing 20 Bcf/d for the first time. The storage surplus to the five-year average has narrowed from 68 Bcf to 45 Bcf in a week. South Central salt storage sits 15.4% below its five-year average. The fundamentals that matter for January are getting tighter while the weather that matters for late October is getting softer.

The longer view frames the move. Natural gas is up 6.1% over the past month but 13.4% lower than a year ago. The November contract made its first prompt-month settlement at $3.01 on September 29, rose to $3.24 by October 15, and has now returned below that starting level. Month to date through October 15, November futures averaged $3.15 per MMBtu. Tuesday’s $2.975 sits 5.6% below that average.

Trading volume has fallen since late September. Thin participation amplifies weather-driven moves, which explains part of the sharp two-day slide from $3.24 to below $3.00. Deferred contracts have held up better than the prompt month, which shows that traders are selling November’s mild weather while protecting their winter exposure.

The levels that matter are clear. Support sits at $2.95, then $2.90 and $2.85. Resistance sits at $3.058, Monday’s settlement, then $3.20, $3.24 and the $3.30 October high. The November contract expires on October 28, so the prompt-month dynamics will shift to December within six sessions.

Bearish Weather Pushed November Below Technical Support

The weather is the single biggest reason for Tuesday’s decline. Strong production and benign shoulder-season forecasts weighed on futures from the opening bell. The latest outlooks call for weaker-than-normal heating demand across the northern United States into late October, removing the early-season furnace demand that traders had begun to price.

The shift has been fast. The previous week brought northern chills that ignited furnaces and southern heat that kept air conditioners running, which pushed physical weekly prices higher. That combination of heating and cooling demand supported the November contract above $3.20. The new forecasts remove both. With neither heating nor cooling demand elevated, late October falls into the shoulder-season demand lull.

Power demand confirms the weakness. Gas burned for power generation fell 5.8 Bcf/d week over week. Mild temperatures reduce electricity demand, and blustery winds have lifted wind generation, which displaces gas-fired power. Strong wind output is one reason storage injections are expected to pick up in the coming week.

The decline started on Monday. Natural gas futures retreated even as LNG feedgas demand hit a record, with weaker heating demand expectations and the prospect of recovering production weighing on nearby contracts. November settled below technical support on Monday, which set up Tuesday’s follow-through break below $3.00. Futures fell from mid-October highs near $3.30 to about $3.06 by Monday’s close.

The demand outlook improves into November. Total U.S. demand, including exports, is expected to rise as colder weather arrives in early November, a normal seasonal pattern. Heating demand typically ramps sharply through November as the withdrawal season begins. The question for the November contract is whether that ramp starts before expiry on October 28. Current forecasts say it does not.

Weather-driven moves in late October tend to reverse once the first cold snap arrives. Every heating season begins with a shoulder period, and the timing of the first major cold outbreak varies by weeks from year to year. Traders who sold November on mild forecasts are betting that the cold arrives late. Traders holding December and January are betting it arrives on schedule.

LNG Feedgas Crossed 20 Bcf/d for the First Time

The most important structural development in U.S. natural gas came on Monday. Feedgas to U.S. LNG export terminals reached a record 20.7 Bcf/d, surpassing 20 Bcf/d for the first time. A decade after the first LNG cargo from the Lower 48 left Sabine Pass, export demand has become the largest single source of growth in U.S. gas consumption.

The infrastructure behind that number is expanding. The United States now has eight operating LNG terminals, with seven more under construction. Feedgas averaged about 18.2 Bcf/d in the week ending October 11, up 0.4 Bcf/d from the prior week, as Freeport and Cove Point returned from maintenance. Freeport LNG Train 2 was down for maintenance from October 2 to 8, and Cove Point was down for annual maintenance from September 19 until it returned to full operations on October 12.

Golden Pass is the key new contributor. The commissioning terminal took in less than 300 MMcf/d at the start of the week ending October 11 but reached record levels above 600 MMcf/d over the following weekend. October has seen intake days as high as 690 MMcf/d. Between April and the end of September, feedgas to Golden Pass’s commissioning train averaged just 300 MMcf/d, with periods when it took little or no gas. The ramp-up at Golden Pass is one of the main reasons feedgas crossed 20 Bcf/d.

Other projects are adding volume. Plaquemines LNG and Corpus Christi Stage 3 have ramped up, and LNG Canada has begun initial commissioning flows. U.S. LNG exports averaged 17.4 Bcf/d in the first half of 2026, up 23% from the first half of 2025. Export capacity reached 18.3 Bcf/d in April, up from 15.4 Bcf/d in October 2025. U.S. LNG exports are on track to exceed 120 million tonnes in 2026.

The year-to-date comparison shows the scale of the shift. Feedgas volumes have averaged 2.4 Bcf/d higher through October 14 than in the same period of 2025, a 15.7% increase. For October month to date, volumes are nearly 8% higher than a year ago.

The record is unlikely to hold for long. With Golden Pass ramping and winter demand for LNG rising in Europe and Asia, feedgas is heading into another record-breaking winter. Each additional Bcf/d of LNG demand removes gas that would otherwise go into storage, which tightens the domestic balance through the withdrawal season.

Storage Surplus Shrinks to 45 Bcf as South Central Salt Runs 15.4% Low

The storage data shows a market that is tighter than the price suggests. U.S. Lower 48 working gas rose 67 Bcf to 3,567 Bcf in the week ending October 9, according to the Energy Information Administration’s weekly report. The injection was 23 Bcf below the five-year average of 90 Bcf for the same week. The smaller build pushed futures up 37 ticks on the release.

The surplus to normal is shrinking. Inventories stood 45 Bcf, or 1.3%, above the five-year average of 3,522 Bcf. A week earlier, the surplus was 68 Bcf, or 2.0%. In one week, a fifth of the cushion disappeared. Stocks were 143 Bcf below the level a year earlier, widening from a 130 Bcf deficit the week before.

The prior week shows the trend. The EIA reported an 85 Bcf injection for the week ending October 2, the largest since late June, which lifted stocks to 3,500 Bcf. That build exceeded the 79 Bcf estimate but still fell short of the 96 Bcf five-year average. The week before brought a 64 Bcf build against an 80 Bcf average. Injections have run below normal for three straight weeks.

The South Central region is the pressure point. South Central salt storage, the most flexible and responsive storage in the country, held 236 Bcf in the week ending October 9. That level is 15.4% below the five-year average and 21.9% below a year earlier. Salt caverns can inject and withdraw gas quickly, which makes them critical for managing short-term demand spikes in winter. Nonsalt storage in the region held 861 Bcf, 0.9% below the five-year average.

The low salt levels sit right next to the LNG terminals. Most U.S. export terminals are on the Gulf Coast, where South Central storage is concentrated. Record feedgas is drawing gas from the same region where flexible storage is tightest.

The next report arrives Thursday. Estimates for the week ending October 16 point to an 82 Bcf injection, against 86 Bcf a year earlier and a five-year average of 87 Bcf. The range of estimates runs from 72 to 87 Bcf. An 82 Bcf build would narrow the surplus by another 5 Bcf. An injection near the low end at 72 Bcf would cut the surplus to around 30 Bcf and likely lift prices.

Production Fell From 113.3 Bcf/d Records to an Eight-Month Low

The supply side has been volatile, and its recovery is part of what pushed futures below $3.00. Lower 48 natural gas production hit record highs of 113.3 Bcf/d in August and September. In October, output averaged between 110.6 and 111.3 Bcf/d, depending on the measure. On October 13, daily output was on track to drop to an eight-month low of around 107.1 Bcf/d.

Hurricane Isaias caused part of the decline. Approximately 1.26 Bcf/d, or 58.8% of Gulf offshore natural gas production, was shut in on October 9. By October 14, shut-ins had fallen to 0.24 Bcf/d, or 11.1%, as offshore operations resumed. The storm also drove the November contract to $3.30 as it approached the Gulf, before forecasts turned milder and prices fell back to $3.17 by October 12.

Pipeline problems added to the dip. Force majeure incidents and outages on pipelines in Kentucky, Texas, West Virginia and elsewhere cut supply over the past month. The largest was a Columbia Gas Transmission restriction in Appalachia, which caused Appalachian cash prices to plunge as gas was trapped in the region. That restriction has now ended, and Appalachian pipeline flows have rebounded.

The return of supply is bearish for the prompt month. Total supply fell 2.3% to 111.1 Bcf/d last week, with dry gas production down 2.9 Bcf/d, most of it in the South Central region. As Gulf offshore output recovers and Appalachian gas reaches markets again, production will move back toward its record levels. Net imports from Canada rose 0.3 Bcf/d to 5.3 Bcf/d.

The year as a whole is still a record. Year-to-date production through October 16 averaged 4.1% higher than the same period in 2025, putting 2026 on pace for a new annual record. October month-to-date production was 3.4% higher than a year earlier but 1.7% below September. Associated gas from oil fields supports output, and with WTI near $96 to $104, oil producers have every incentive to keep drilling.

The production recovery is the main bearish argument for the next two weeks. If output returns to 113 Bcf/d while weather stays mild, injections will run near or above normal into the end of October, and the storage surplus will stop shrinking. That scenario would keep the November contract below $3.00 into expiry.

The EIA Sees $3.48 Henry Hub for 2026 and $3.16 for 2027

The official forecast frames the longer-term outlook. In its October Short-Term Energy Outlook, the EIA nudged its 2026 Henry Hub forecast up to $3.48 per MMBtu but cut its 2027 forecast to $3.16, as production growth is expected to outpace demand. At $2.975, the November contract trades 14.5% below the 2026 average forecast.

The storage outlook in the same report is more comfortable than the weekly data. According to the EIA’s natural gas outlook, the agency estimated U.S. inventories at 3,523 Bcf at the end of September and forecast a build of 328 Bcf during October, slightly less than average, to reach 3,850 Bcf at the end of October. That would put inventories 2% above the five-year average to start the heating season on November 1.

The weekly data is running behind that path. Through October 9, inventories reached 3,567 Bcf. Assuming an 82 Bcf injection for the week ending October 16 and five-year average builds for the rest of October, Lower 48 storage would enter the withdrawal season at around 3,793 Bcf. That is 57 Bcf below the EIA’s 3,850 Bcf forecast. The gap means the market enters winter with less cushion than the official outlook assumed.

The difference matters for winter pricing. A 57 Bcf shortfall relative to the forecast is roughly the size of one cold week’s net withdrawal. If winter arrives on schedule and LNG feedgas stays above 20 Bcf/d, storage could fall below the five-year average by December. A winter storage deficit remains possible even after the current dip.

The EIA’s 2027 forecast reflects the supply side. Production growth from the Permian, Haynesville and Appalachia is expected to outpace demand next year, even with new LNG capacity. That forecast assumes no major supply disruptions and normal weather. It also assumes LNG export capacity ramps on schedule, which has not always happened. Golden Pass took months longer than expected to reach meaningful volumes.

For the forecast, the EIA numbers set a reasonable range. A 2026 average of $3.48 implies higher prices in November and December than the current $2.975. A 2027 average of $3.16 implies that the winter peak will fade as production catches up. The current price sits below both, which suggests that the market has priced in a softer winter than the official outlook.

Europe Pays $28.43 for Gas While Henry Hub Trades Below $3

The global gas market shows why U.S. LNG demand keeps growing. On Monday, the European TTF benchmark traded at $28.43 per MMBtu and Asia’s JKM benchmark at $29.77. Henry Hub stood at $3.04. The TTF-Henry Hub spread was $25.39 per MMBtu. The U.S. Gulf Coast netback to Europe, the price a U.S. exporter receives after shipping and liquefaction costs, was about $26.03 per MMBtu.

That spread is the engine of U.S. exports. U.S. LNG is typically sold under contracts linked to Henry Hub plus a fixed liquefaction fee, while European buyers pay TTF or another hub price. With a spread of $25 per MMBtu, every terminal that can run at capacity will, because the economics are overwhelmingly favorable. As long as international prices stay near $28 to $30, U.S. feedgas will stay at maximum.

The Middle East explains the global premium. The Strait of Hormuz carries about a fifth of the world’s crude oil and liquefied natural gas in normal times. Since the war waged by the United States and Israel against Iran began on February 28, flows through the strait have been disrupted. Qatar, one of the world’s largest LNG exporters, ships its cargoes through Hormuz. Lower global supply from the Middle East has incentivized U.S. companies to sell LNG abroad.

European gas fell on Tuesday. TTF dropped 3.89% to €84.61 per megawatt-hour, tracking the reversal in oil after Brent spiked to $111.75 and then fell to $106.85. European gas has followed oil this month as both respond to Gulf headlines. Asian buyers are competing for the same cargoes, and an active JKM-TTF arbitrage window has pulled Atlantic cargoes into the Pacific.

Non-Gulf LNG supply has grown 25% from a year earlier, as U.S. terminals, LNG Canada and other new projects fill the gap left by disrupted Middle East flows. That growth is why international prices are near $28 rather than higher. U.S. LNG has become the global swing supply.

For Henry Hub, the global picture is a long-term floor. Domestic production of 109.7 to 112.2 Bcf/d, supported by associated gas, cushions the U.S. market against international volatility. Henry Hub averaged near $3.19 through most of October while TTF traded nine times higher. But every Bcf/d of new export capacity pulls the domestic market closer to global prices. With feedgas above 20 Bcf/d, the structural floor under Henry Hub has risen.

The Oil Link: Associated Gas Keeps Supply Flowing

The oil market affects natural gas in two ways, and right now they pull in opposite directions. High oil prices support drilling in oil-rich basins, where gas comes out of the ground as a byproduct. That associated gas adds to supply regardless of gas prices. On the demand side, high oil prices push some industrial users and power generators toward gas, adding demand.

The supply effect dominates in the near term. With Brent at $106.85 and December WTI at $96.17 on Tuesday, oil producers in the Permian Basin have every incentive to keep drilling. Permian associated gas has been one of the main drivers of record U.S. production in 2026. Even if Henry Hub falls toward $2.50, oil-directed drilling would keep associated gas flowing.

That dynamic explains the EIA’s lower 2027 forecast. If oil stays high through 2027, associated gas will keep growing, adding supply that outpaces LNG demand growth. The structural tightening from LNG would be offset by the structural loosening from associated gas.

The Gulf conflict raises the stakes for both. Tuesday’s oil spike came on Houthi claims of strikes at Saudi Arabia’s Yanbu export facility and Shaybah oilfield. Brent touched $111.75 before falling $4.90. A confirmed disruption would push oil higher, which would sustain associated gas production in the United States. It would also push international LNG prices higher, which would sustain U.S. export demand. Both effects would hit at once.

Natural gas liquids add another channel. Gas from oil fields is often wet, containing ethane, propane and butane that are separated and sold. High oil prices lift the value of those liquids, which improves the economics of wet gas production even when the dry gas price is low.

The oil link also shows up in the equity market. Energy stocks barely moved during Tuesday’s oil spike, with Chevron up 0.20% and Exxon down 0.24%. Gas-focused producers trade more on Henry Hub than on oil. EQT, the largest U.S. gas producer, and Coterra, with exposure to both oil and gas, will be sensitive to whether November’s weakness extends into winter.

The forecast assumes oil stays between $95 and $112 for Brent through the end of the year. In that range, associated gas supply remains strong, which caps the upside for Henry Hub but does not prevent a winter rally.

The Forward Curve Prices a Winter Premium

The structure of the futures curve shows how traders see the next few months. Deferred contracts showed resilience on Monday even as the November contract retreated. Traders sold the prompt month on mild late-October forecasts while holding winter contracts, which keeps the curve in contango, with later months trading above nearer months.

Contango in natural gas reflects storage economics. When the near month is weak and later months are firm, traders can buy gas now, store it and sell it forward at a profit. That trade supports injections in October, which is part of why the storage data matters so much right now. A wide contango encourages storage. A narrow one discourages it.

The November contract’s history this month shows the volatility. Its first prompt-month settlement was $3.01 on September 29. It rose to $3.24 by October 15, up 7.6%. It touched $3.30 on Hurricane Isaias. It fell back to $3.17 by October 12, then rebounded on the smaller storage build. It now trades at $2.975. The contract has swung by 32.5 cents from high to low in October, more than 10% of its value.

The September comparison adds context. The November contract settled at $3.37 on September 24, before it became the prompt month. It has fallen 39.5 cents, or 11.7%, since then. Traders priced a tighter winter in late September than they price today.

Expiry is close. The November contract expires on October 28. In the days before expiry, prompt-month prices can swing sharply as traders roll positions into December and as physical buyers lock in November supply during bidweek. Weather forecasts in the final week will dominate.

The December contract becomes the prompt month after that. December typically trades at a premium to November because it covers a full month of winter heating demand. When the roll happens, the prompt-month price on charts will likely jump, even though no individual contract moved. Traders should focus on the December contract’s level when assessing the winter outlook.

For the forecast, the curve says the market expects higher prices into winter. The November weakness is a timing issue, not a change in the seasonal path.

Technical Map: $3.00 Lost, $2.85 Support, $3.30 Ceiling

The chart for the November contract shows a clear break. The contract settled below technical support on Monday and broke below $3.00 on Tuesday. The $3.00 round number had acted as support through most of October, and its loss opens the lower part of the range.

Support levels sit below. The $2.95 area is the first, near Tuesday’s intraday trading. The $2.90 level is next, followed by $2.85. The contract fell below $3.00 earlier in October before recovering, and that earlier low sits in this zone. A break below $2.85 would put the November contract at its lowest level of the autumn.

Resistance is layered above. Monday’s settlement near $3.058 is the first barrier, 2.8% above the current price. The $3.20 level, near the November contract’s mid-October trading, sits 7.6% higher. The October 15 settlement at $3.24 sits 8.9% higher. The $3.30 October high, set on the Hurricane Isaias spike, sits 10.9% higher. The September 24 settlement at $3.37 sits 13.3% higher.

Spot prices give a reference. Henry Hub spot averaged $3.121 on Tuesday morning, 14.6 cents above the futures price. When spot trades above the prompt futures contract, physical buyers are paying more for gas today than traders expect to pay in November. That premium supports the case that the futures selloff is driven by forecast changes rather than by a physical glut.

The weekly ranges have been wide. A 32.5-cent swing in October equals 11% of the current price. Daily moves of 8 cents are common. The volatility reflects thin trading volume and a market caught between bearish weather and bullish structural factors.

Thursday’s storage report is the next technical catalyst. A build below 82 Bcf would likely send the November contract back above $3.00 and toward $3.06. A build above 87 Bcf, the five-year average, would confirm the bearish weather view and push the contract toward $2.90. The report will be the last storage data before November’s expiry that reflects a full week of current conditions.

Three Scenarios for Natural Gas Into Winter

The forecast comes down to three paths, defined by weather, production and LNG demand.

The base case, a 50% probability, is a dip followed by a winter recovery. The November contract stays between $2.85 and $3.06 into its October 28 expiry as mild weather persists and production recovers. Thursday’s storage report shows an injection near 82 Bcf. After the roll to December, the prompt contract trades between $3.20 and $3.40 as heating demand ramps in November and LNG feedgas holds above 20 Bcf/d. Storage enters the withdrawal season near 3,793 Bcf, below the EIA’s 3,850 Bcf forecast.

The bullish scenario, a 30% probability, is an early cold snap. Weather forecasts shift colder for early November, Thursday’s storage build comes in near 72 Bcf, and LNG feedgas sets new records as Golden Pass ramps. The storage surplus falls below 30 Bcf. The November contract rallies back above $3.20 before expiry, and December trades toward $3.50 to $3.70. A confirmed disruption in the Gulf that pushes international LNG prices higher would add to the move.

The bearish scenario, a 20% probability, is a warm start to winter. Mild weather extends into mid-November, production returns to 113 Bcf/d records, and injections run above the five-year average. The storage surplus widens back toward 70 Bcf. The November contract falls to $2.75 into expiry, and December struggles to hold $3.00. A de-escalation in the Gulf that sends international LNG prices lower would narrow the export spread and reduce U.S. feedgas.

The skew reflects the structural factors. LNG demand above 20 Bcf/d and a shrinking storage surplus make a deep and lasting decline unlikely. Weather is the wild card, and late-October forecasts often change sharply as the season turns.

The upside depends on timing. A cold snap in early November would hit a market with less storage cushion than the official forecast assumed. A delayed winter would push the rally into December or January.

Natural Gas Forecast Verdict: Buy the $2.85-$2.95 Zone, Target $3.30

The verdict on natural gas is bullish on a medium-term view, with a target of $3.30, 10.9% above the November contract’s current price of $2.975. The break below $3.00 reflects mild late-October weather and recovering production. November futures fell 8.3 cents to $2.975 on Tuesday, power burn dropped 5.8 Bcf/d week over week, and Appalachian supply returned after a Columbia Gas Transmission outage ended. Those factors weigh on the prompt month into its October 28 expiry.

The structural picture points the other way. LNG feedgas hit a record 20.7 Bcf/d on Monday, the first time above 20 Bcf/d, with Golden Pass ramping and seven more terminals under construction. Feedgas is running 15.7% above last year. The storage surplus to the five-year average fell from 68 Bcf to 45 Bcf in a single week. South Central salt storage, the most flexible storage near the export terminals, sits 15.4% below its five-year average. Storage is on track to enter winter near 3,793 Bcf, 57 Bcf below the EIA’s 3,850 Bcf forecast. The TTF-Henry Hub spread of $25.39 per MMBtu keeps every U.S. export terminal running at capacity.

The official outlook supports higher prices. The EIA forecasts a 2026 Henry Hub average of $3.48, 17% above the current price. Henry Hub spot traded at $3.121 on Tuesday, above the futures contract.

The trade is to buy the $2.85 to $2.95 zone, with a stop on a daily close below $2.75, targeting $3.20 first and $3.30 next. That sets downside to the stop at 7.6% against upside to the target of 10.9%. Traders using the December contract should apply the same logic relative to its level after the roll. A close above $3.06 would confirm that the sub-$3 break has failed. A close below $2.75 would shift the view to neutral until colder weather arrives.

Natural gas is cheap right now because late October is warm. Winter is not. With record export demand and a shrinking storage cushion, the first cold snap of November will hit a market that is tighter than its price.

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